1. Field of the Invention
The present invention relates to reducing pressure of a circulating fluid in a wellbore. More particularly, the invention relates to reducing the pressure brought about by friction as the fluid moves in a wellbore. More particularly still, the invention relates to controlling and reducing downhole pressure of circulating fluid in a wellbore to prevent formation damage and loss of fluid to a formation.
2. Description of the Related Art
Wellbores are typically filled with fluid during drilling in order to prevent the in-flow of production fluid into the wellbore, cool a rotating bit, and provide a path to the surface for wellbore cuttings. As the depth of a wellbore increases, fluid pressure in the wellbore correspondingly increases developing a hydrostatic head which is affected by the weight of the fluid in the wellbore. The frictional forces brought about by the circulation of fluid between the top and bottom of the wellbore create additional pressure known as a “friction head.” Friction head increases as the viscosity of the fluid increases. The total effect is known as an equivalent circulation density (ECD) of the wellbore fluid.
In order to keep the well under control, fluid pressure in a wellbore is intentionally maintained at a level above pore pressure of formations surrounding the wellbore. Pore pressure refers to natural pressure of a formation urging fluid into a wellbore. While fluid pressure in the wellbore must be kept above pore pressure, it must also be kept below the fracture pressure of the formation to prevent the wellbore fluid from fracturing and entering the formation. Excessive fluid pressure in the wellbore can result in damage to a formation and loss of expensive drilling fluid.
Conventionally, a section of wellbore is drilled to that depth where the combination of the hydrostatic and friction heads approach the fracture pressure of the formations adjacent the wellbore. At that point, a string of casing must be installed in the wellbore to isolate the formation from the increasing pressure before the wellbore can be drilled to a greater depth. In the past, the total well depth was relatively shallow and casing strings of a decreasing diameter were not a big concern. Presently, however, so many casing strings are necessary in extended reach deep (ERD) wellbores that the path for hydrocarbons at a lower portion of the wellbore becomes very restricted. In some instances, deep wellbores are impossible to drill due to the number casing of strings necessary to complete the well. Graph 1 illustrates this point, which is based on a deepwater Gulf of Mexico (GOM) example.
In Graph 1, dotted line A shows pore pressure gradient and line B shows fracture gradient of the formation, which is approximately parallel to the pore pressure gradient but higher. Circulating pressure gradients of 15.2-ppg pounds per gallon) drilling fluid in a deepwater well is shown as line C. Since friction head is a function of distance traveled by the fluid, the circulation density line C is not parallel to the hydrostatic gradient of the fluid (line D). Safe drilling procedure requires circulating pressure gradient (line C) to lie between pore pressure and fracture pressure gradients (lines A and B). However, as shown in Graph 1, circulating pressure gradient of 15.2-ppg drilling fluid (line C) in this example extends above the fracture gradient curve at some point where fracturing of formation becomes inevitable. In order to avoid this problem, a casing must be set up to the depth where line C meets line B within predefined safety limit before proceeding with further drilling. For this reason, drilling program for GOM well called for as many as seven casing sizes, excluding the surface casing (Table 1).
TABLE 1Planned casing program for GOM deepwater well.Casing sizePlanned shoe depth(in.)(TVD-ft)(MD-ft)303,0423,042204,2294,229165,5375,53713-3758,0168,01611-3/813,62213,690 9-5/817,69618,171 724,31925,145 525,77226,750
Another problem associated with deep wellbores is differential sticking of a work string in the well. If wellbore fluid enters an adjacent formation, the work string can be pulled in the direction of the exiting fluid due to a pressure differential between pore and wellbore pressures, and become stuck. The problem of differential sticking is exacerbated in a deep wellbore having a work string of several thousand feet. Sediment buildup on the surface of the wellbore also causes a work string to get stuck when drilling fluid migrates into the formation.
The problem of circulation wellbore pressure is also an issue in under balanced wells. Underbalanced drilling relates to drilling of a wellbore in a state wherein fluid in the wellbore is kept at a pressure below the pore pressure of an adjacent formation. Underbalanced wells are typically controlled by some sort of seal at the surface rather than by heavy fluid in the wellbore. In these wells, it is necessary to keep any fluid in the wellbore at a pressure below pore pressure.
Various prior art apparatus and methods have been used in wellbores to effect the pressure of circulating fluids. For example, U.S. Pat. Nos. 5,720,356 and 6,065,550 provide a method of underbalanced drilling utilizing a second annulus between a coiled tubing string and a primary drill string. The second annulus is filled with a second fluid that commingles with a first fluid in the primary annulus. The fluids establish an equilibrium within the primary string. U.S. Pat. No. 4,063,602, related to offshore drilling, uses a valve at the bottom of a riser to redirect drilling fluid to the sea in order to influence the pressure of fluid in the annulus. An optional pump, located on the sea floor provides lift to fluid in the wellbore. U.S. Pat. No. 4,813,495 is a drilling method using a centrifugal pump at the ocean floor to return drilling fluid to the surface of the well, thereby permitting heavier fluids to be used. U.S. Pat. No. 4,630,691 utilizes a fluid bypass to reduce fluid pressure at a drill bit. U.S. Pat. No. 4,291,772 describes a sub sea drilling apparatus with a separate return fluid line to the surface in order to reduce weight or tension in a riser. U.S. Pat. No. 4,583,603 describes a drill pipe joint with a bypass for redirecting fluid from the drill string to an annulus in order to reduce fluid pressure in an area where fluid is lost into a formation. U.S. Pat. No. 4,049,066 describes an apparatus to reduce pressure near a drill bit that operates to facilitate drilling and to remove cuttings.
The above mentioned patents are directed either at reducing pressure at the bit to facilitate the movement of cuttings to the surface or they are designed to provide some alternate path for return fluid. None successfully provide methods and apparatus specifically to facilitate the drilling of wells by reducing the number of casing strings needed.
There is a need therefore, for an improved pressure reduction apparatus and methods for use in a circulating wellbore that can be used to effect a change in wellbore pressure. There is a further need for a pressure reduction apparatus tool and methods for keeping fluid pressure in a circulating wellbore under fracture pressure. There is yet a further need for a pressure reduction apparatus and methods permitting fluids with a relatively high viscosity to be used without exceeding formation fracture pressure.
There is yet a further need for an apparatus and methods to effect a reduction of pressure in an underbalanced wellbore while using a heavyweight drilling fluid. There is yet a further need for an apparatus and methods to reduce pressure of circulating fluid in a wellbore so that fewer casing stings are required to drill a deep wellbore. There is yet a further need for an apparatus and method to reduce or to prevent differential sticking of a work string in a wellbore as a result of fluid loss into the wellbore.